Chemical compositions and methods for remediating hydrogen sulfide and other contaminants in hydrocarbon based liquids and aqueous solutions without the formation of precipitates or scale

ABSTRACT

A treatment process for remediating a contaminated liquid containing more than 5 ppm hydrogen sulfide (H2S) and substantially without formation of precipitate, includes steps of steps of adding an aqueous solution containing at least one hydroxide compound at a collective concentration of 35-55 wt % to the contaminated liquid to achieve a concentration of 125-5000 ppm of the hydroxide compounds in the contaminated liquid, adding at least one organic acid and to the liquid to achieve a concentration of 0.01-10 ppm in the contaminated liquid, and dispersing the aqueous solution and the at least one organic acid in the contaminated liquid and allowing the aqueous solution and the at least one organic acid to react with the contaminated liquid for a period of time until a concentration of hydrogen sulfide in the contaminated liquid is reduced to ≤5 ppm.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of International Patent ApplicationNo. PCT/US2018/064015, filed on Dec. 5, 2018, which claims the benefitof priority to US Provisional Patent Application Nos. 62/661,289, filedApr. 23, 2018 and 62/702,960, filed Jul. 25, 2018 And, PCT/US2018/064015is a Continuation-in-Part of International ApplicationPCT/US2018/050913, filed 13 Sep. 2018, which claims priority to U.S.Provisional Patent Application No. 62/539,699, filed Aug. 1, 2017. Theentire subject matter of each of these priority applications isincorporated by reference herein.

BACKGROUND OF THE INVENTION 1. Field of the Invention

The present disclosure relates to novel treatment solutions and methodsof using same for treating and remediating sulfur-containing compounds,primarily including hydrogen sulfide (H₂S), and other contaminants inhydrocarbon-petroleum based liquids and contaminated aqueous solutions,and substantially without formation of any precipitates, scaling or thelike. More particularly, the present disclosure relates to suchtreatment solutions and methods in which the treatment solutions areadded to the hydrocarbon-petroleum based liquids or contaminated aqueoussolutions in a controlled and efficient manner which safely andefficiently remediates the contaminants down to acceptable levels,substantially without the formation of any precipitates, scaling or thelike, and without otherwise detrimentally affecting thehydrocarbon-petroleum based liquids or contaminated aqueous solutions inany significant manner.

2. Background Art

Sulfur-containing compounds including hydrogen sulfide (H₂S) have longbeen recognized as undesirable contaminants in hydrocarbon or petroleumbased liquids such as crude oil and liquified petroleum gas (LPG), aswell as in contaminated aqueous solutions such as solutions extractedfrom the earth along with crude oil, natural gas and the like, whichaqueous solutions may also be contain significant concentrations ofsalts and be considered brine. Herein “hydrocarbon based liquid” is usedto indicated any hydrocarbon based liquid, including petroleum basedliquids. Examples of hydrocarbon based liquids which may be treated withthe treatment solutions and treatment methods of the present inventioninclude those containing molecules of CH₉ to CH₃₂. H₂S is a particularlyundesirable contaminant because it is highly toxic, corrosive, etc. andgenerally petroleum based liquids such as crude oil should contain lessthan five ppm H₂S in order to be acceptable for refining or otherprocessing. While the amount of H₂S in hydrocarbon based liquids canrange from a few ppm to more than 100,000 ppm, crude oil from the groundtypically contains ≤40,000 ppm H₂S, most often ≤2000 ppm H₂S, and willgenerally be somewhat acidic with a pH about 5 to 6. The H₂S may bepresent in several forms, including H₂S dissolved in a liquid, H₂S asmercaptan sulfur and H₂S content in vapor, but the majority is typicallypresent as H₂S content in vapor, particularly at higher concentrations,and the release of H₂S in vapor or gaseous form is particularly toxicand dangerous.

Generally, much of the H₂S in a hydrocarbon based liquid, such as crudeoil, is in gaseous or vapor form. H₂S gas has much greater solubility inhydrocarbon based liquids than in water, and at the high pressures atwhich crude oil exists underground, it is possible for the crude oil tohave thousands and tens of thousands of ppm H₂S therein. However, whenthe crude oil is brought up to ambient or atmospheric pressure much ofthe H₂S gas therein may be released from the crude oil according toHenry's Law, and hence the need to remediate the H₂S and prevent it frombeing released. The amount of soluble and gaseous H₂S which can be inaqueous solutions is less than the amount which may be in hydrocarbonbased liquids, but it still can be present in hundreds and thousands ofppm, and contaminated aqueous solutions will typically contains ≤1000ppm H₂S. Generally, H₂S is an acidic compound, crude oil as extractedfrom the ground and containing a typical amount of H₂S, e.g. ≤2000 ppm,which is mostly in the form gas dissolved in the crude oil, has amoderately acidic pH of about 5-5.5. Gaseous H₂S does not exist insolution above a pH of about 7.

There are many known methods for remediating sulfur-containingcompounds, including H₂S, from crude oil and other liquids. For example,M. N. Sharak et al., Removal of Hydrogen Sulfide from HydrocarbonLiquids Using a Caustic Solution, Energy Sources, Part A: Recovery,Utilization, and Environmental Effects, 37:791-798, 2015, discuss that:the known methods include amine processes involving monoethanolamine(MEA), triazine, etc., treatment involving use of caustic material, ironoxide process, zinc oxide, molecular sieve, potassium hydroxide, and ahydrodesulphurization process; the amine treatment is usually the mostcost effective choice for gas sweetening when significant amounts ofacid gases exist; scrubbing of hydrogen sulfide using sodium hydroxidesolution is a well established technology in refinery applications;caustic wash process is commonly used as a preliminary step insweetening liquid hydrocarbons; and since the used solvent in thisprocess cannot be easily regenerated, caustic scrubbers are most oftenapplied where low acid gas (H2S) volumes must be treated.

H₂S abatement achieved by a conventional amine treatment process whichuses an amine such as monoethanolamine (MEA) or triazine for treatingH₂S in crude oil. However, with the conventional amine treatmentprocess, while the H₂S may be initially remediated or abated down toacceptable levels, the sulfur contained in the treated oil mayundesirably revert back to H₂S over time, especially if the treated oilis heated.

Somewhat similarly, it is also known that there are bacteria whichingest sulfur compounds, and hence may reduce the amounts of sulfurcontaminants in hydrocarbon based liquids or contaminated aqueoussolutions. However, when the bacteria die and decompose this undesirablyreleases the sulfur back into the hydrocarbon based liquids orcontaminated aqueous solutions.

A typical caustic treatment used to remediate H₂S in crude oil involvesuse of a caustic aqueous solution consisting of up to 20% NaOH byweight. The water and caustic material are used to extract H₂S from thecrude oil into solution, dissociating H₂S to HS— ion at higher pH, whichshifts the equilibrium of H₂S gas from oil to water. Then, the HS— canreact with sodium to form NaHS (sodium bisulfide), or with S₂— to formNa₂S (sodium sulfide), for example, plus water as a byproduct accordingto the following equations.H₂S+NaOH→NaHS+H₂O  (1)NaHS+NaOH→Na₂S+H₂O  (2)Generally, the conventional caustic treatment methods are limited tousing caustic solutions of only up to 20 weight percent NaOH because theconventional methods are designed and intended to be partly aliquid-liquid extraction, and partly a chemical reaction to convert theH₂S gas to a solid sulfurous species. It is conventionally understoodthat a certain amount of water is needed to permit the chemicalreactants to contact with the crude oil or other petroleum based liquid.The larger amounts of water contained in the conventional caustictreatment solutions permit a greater amount of liquid-liquid extraction.Also, it is known that use of excessive amounts of NaOH may damage thecrude oil, as well as metal components used handling the crude oil suchas pipes and tanks.

Additionally, some of the H₂S may be converted into sulfur dioxide (SO₂)gas, e.g., upon stirring which allows air containing oxygen to get intothe oil, which may be released from the treated petroleum based liquid,depending on the pressure under which the treated liquid is kept.Generally, hydroxides including NaOH are reducing agents and would notproduce sulfur dioxide or elemental sulfur if the treated hydrocarbonbased liquid is not exposed to air. However, if the oil is exposed toair, the sulfide/bisulfide can be oxidized to SO₂ or to elementalsulfur. All sulfide species are the same oxidation state (−2) and NaOHis not changing the oxidation state. Similar reactions would occur forother hydroxides included in the treatment solution. Relative to anysuch sulfur dioxide (SO₂) gas, as well as any other gases that may bereleased from the treated crude oil, it would be necessary as a safetymeasure to provide some head space in a closed tank or other closedvessel transporting the treated liquid to assure that the pressure doesnot get excessively high.

Recently, the present inventors have proposed another process, as setforth in U.S. Provisional Patent Application No. 62/539,699 andInternational Application PCT/US2018/050913, for remediatingsulfur-containing compounds, including H₂S, from hydrocarbon basedliquids including crude oil, and from contaminated aqueous solutions,using an aqueous treatment solution containing primarily a highconcentration of one or more hydroxides. The recently proposed treatmentsolution may include other, secondary components such as ananti-bacterial agent for killing any undesired bacteria that may bepresent and grow in the treated liquids, and/or an agent for causingsome gas(ses) in a treated liquid to be released, but the primarycomponent is the collectively high concentration of one or morehydroxides. In the recently proposed treatment process, the recentlyproposed treatment solution is added to the hydrocarbon based liquids oraqueous solutions at appropriate dosage rates depending on multiplefactors such that the hydroxide(s) efficiently remediate thesulfur-containing compounds within a desired time period, and withoutotherwise detrimentally affecting the hydrocarbon-petroleum basedliquids or contaminated aqueous solutions in any significant manner.

According to their recent proposal, the present inventors havediscovered that the conventional treatment method using a causticaqueous solution consisting of up to 20% NaOH by weight is notefficient, and that the H₂S can be much more efficiently remediatedusing the recently proposed treatment solution containing a very highconcentration of hydroxides, e.g., including as a primary component35-55 weight percent, and preferably at least 45 weight percent, of oneor more hydroxides, such as sodium hydroxide (NaOH) and potassiumhydroxide (KOH). H₂S gas is more soluble in oil than in water, so that arate-limiting step, in the remediation of H₂S from crude oil, istypically the mass transfer of H₂S from the oil phase into the aqueousphase.

More particularly, they have discovered that: 1) the liquid-liquidextraction aspect of the conventional methods is actually not thatimportant in comparison to the chemical reaction aspect. e.g., becausethe initial solubility of H₂S into water, as given by Henry's Law, islow; 2) the larger amounts of water used in aqueous treatment solutionsaccording to the conventional methods also function to dilute the NaOHand transfer the H₂S from the hydrocarbon liquid into the water withoutabating the H₂S, which is undesirable because this slows the processneeded to produce ionized HS— and S₂— ions that allow more of the H₂Scontained in the petroleum liquids into solution, and 3) it is much moreefficient and effective to remove the sulfur-containing compoundsprimarily though a chemical reaction process and to a much lesser degreea liquid-liquid extraction though use of an aqueous treatment solutioncontaining a collectively high concentration of one or more hydroxides,provided that the amount of hydroxide(s) used is generally limitedwithin a stoichiometrically-based range, although use of higher amountsof the hydroxide(s) may be advantageous in some situations and generallywill not cause any significant problems. Relative to 1) it should benoted that equation (2) above is reversible, so large amounts of waterhydrolyze the sodium sulfide (Na₂S) back to NaOH and NaHS. In otherwords, equation (2) in the reverse direction is a hydrolysis reaction.

According to their recent proposal, the present inventors have foundthat a highly concentrated aqueous treatment solution according to anexemplary embodiment comprising primarily one or more hydroxides, suchas sodium hydroxide (NaOH) and/or potassium hydroxide (KOH) at acollective concentration of 35-55 weight percent, and preferably atleast 45 weight percent, in water is very effective for treatinghydrocarbon based liquids including crude oil, diesel fuel, etc. forremediating contaminants in the hydrocarbon based liquids, including H₂Sand other sulfur-containing contaminants, provided that the amount ofthe aqueous treatment solution used for treating the liquids ismaintained within an appropriate range, which can vary depending onseveral factors, including the specific composition of the liquid to betreated, reaction time permitted and the type of remediation desired,e.g., whether there are any restrictions on the amounts ofprecipitate(s) and gases that may be released from the treated petroleumbased liquids. Sodium hydroxide is very effective for use in thetreatment solution because it does not harm the petroleum based liquidswhen used in appropriate amounts, and is relatively inexpensive,although use of a combination of hydroxides is advantageous for morecompletely reacting with most or all of the sulfides in the petroleumbased liquids, noting that there are more than 300 species of sulfurcompounds, although hydrogen sulfide H₂S is by far the main contaminantthat must be remediated. For example, some other species of undesirablesulfur compounds include ethyl mercaptan (CH₃CH₂SH), dimethyl sufide(C₂H₆S), isobutyl mercatan (C₄H₁₀S) and methyl thiophene (C₅H₆S).Potassium hydroxide is more effective than sodium hydroxide for reactingwith some species of sulfides. Hence, the treatment solution containingpotassium hydroxide (KOH) together with the sodium hydroxide achieves amore complete reaction with all of the sulfides contained in thehydrocarbon based liquids in comparison to just using a concentratedsolution of sodium hydroxide. Such treatment solution according to therecent proposal is highly alkaline with a pH of 13-14.

In a treatment process for remediating contaminated liquids according tothe inventors' recent proposal, their recently proposed treatmentsolution may be added at a standard dosage rate of 0.25-6.0 ml of thetreatment solution/liter of the liquid being treated, preferably 1.0-5.0ml of the treatment solution/liter of the liquid being treated, whichcorresponds to approximately 125-3000 ppm of hydroxide(s) in the liquidbeing treated. Within a relatively short time period such as 15minutes-24 hours after the recently proposed treatment solution is addedto the liquid being treated, it is very effective for remediating theH₂S and other sulfides in most hydrocarbon based liquids including crudeoil and most contaminated aqueous solutions down to safe, acceptablelevels. The specific treatment dosage within the discussed range dependson the characteristics of the particular liquid being treated, includingits viscosity or API density, the particular contaminants it contains,the levels of such contaminants, and allowed reaction time (The term APIas used herein, is an abbreviation for American Petroleum Institute). Atthis dosage level, the H₂S may typically, for example, be remediateddown to less than 5 ppm from initial concentrations of up to 40.000 ppm,and without generating any particularly harmful substances. For example,when the treatment solution includes sodium hydroxide (NaOH) as theprimary hydroxide therein, e.g., at least 90% of all hydroxides in thesolution, much of the H₂S, e.g., at least 60% is converted into sodiumbisulfide (NaHS) according to the reaction (1) above, which remainsdissolved in the treated petroleum liquid, and does not create anysignificant problems that would need to be addressed. Additionally, someof the H₂S may be converted into sulfur dioxide (SO₂) gas which may bereleased from the treated petroleum based liquid, depending on thepressure at which the treated liquid is kept. If the concentration ofH₂S is higher than 20,000 ppm it may be necessary to increase a dosageamount appropriately above the standard dosage rate, which may generallyinvolve linear scalability. Very desirably, the recently proposedtreatment process is generally not reversible in relation to the H₂S andother sulfur contaminants which have been remediated, e.g., even if thetreated liquid is heated up to 180° F. for a period of days or weeks,any remediated sulfur compounds remaining in the treated liquids do notrevert back to H₂S.

Within the discussed range of 0.25-6.0 ml of the treatmentsolution/liter of petroleum based liquid, preferably 1.0-5.0 ml of thetreatment solution/liter of the liquid being treated, the appropriatedosage rate is substantially, linearly scalable in relation to most orall of the various characteristics. For example, if the amount of H₂S isrelatively low, e.g. 20 ppm-100 ppm the dosage rate may be toward thelower end of the range, whereas if the amount of H₂S is relatively high,e.g. 10,000 ppm-20,000 ppm the dosage rate may be toward the higher endof the range, and dosage rates for intermediate amounts of H₂S would beat correspondingly intermediate values of the range. Similar, linearscalability applies based on the viscosity—API gravity of the liquid andreaction times allowed.

Based on the investigations of the present inventors, they have foundthat if the dosage amount of the recently proposed treatment solution,containing one or more hydroxides such as NaOH, KOH, and possibly anantibacterial agent such as potassium silicate, is appropriately withinthe standard dosing rate range, the reaction(s) between the treatmentsolution and the sulfide compounds in the hydrocarbon based liquid,particularly H₂S, proceed quickly and efficiently. By contrast, theyhave also found that if the amount of the treatment solution added isoutside of this range, the reactions between the treatment solution andthe sulfide compounds in the hydrocarbon based liquid may not proceedquickly and/or efficiently. However, the inventors have furtherdetermined that if an intentionally excessive dosage of the recentlyproposed treatment solution is added to a liquid being treated, e.g.,2-5 times the standard dosage rates discussed above, this will likelycause contaminants and remediated contaminants in the treated liquid toprecipitate out of the treated liquid, which may be desirable in somesituations, and will increase the cost of the treatment. Further, theexcess dosages of hydroxides such as NaOH and KOH generally do not haveany significantly adverse effects on the treated petroleum basedliquids, although application of a very excessive amount of thesolution, e.g., ten times the normal amount, may render the treatedpetroleum based liquid caustic which could be damaging to metals such assteel and aluminum used for containing and transporting the treatedliquids.

While the known methods for remediating sulfur-containing compounds,including H₂S, from hydrocarbon based liquid and aqueous solutions,especially the methods and treatment solutions according to the presentinventors' recent proposal are generally effective for remediating theH₂S and other contaminants in the liquids, they remain to be improvedon, particularly in relation to preventing formation of precipitate(s),scaling and the like from the treated liquids. There remains in the arta need for treatment solutions and treatment methods for remediatingsulfur-containing compounds, including H₂S, from crude oil, otherhydrocarbon based liquids, and contaminated aqueous solutions, wheresuch treatment solutions and methods are improved in terms ofeffectiveness in completely remediating the sulfide compounds, as wellas in terms of efficiency in quickly remediating the sulfide compoundsat a reasonable cost, while generating essentially no precipitate(s),scaling and the like in the treated liquids. There is also a need forflexibility in the ability to perform the treatment method atessentially any location, e.g., directly at a well head or an oil fieldwhere crude oil is being extracted, while the crude oil is beingtransported to a refinery, or other location.

SUMMARY OF THE INVENTION

An object of the present invention is to satisfy the above needs in theart.

According to a first aspect of the present invention, a treatmentsolution and treatment process according to the present inventors'recent proposal are modified to include, or is used in combination with,other component(s) which generally are not involved in remediating theH₂S and other contaminants, but function to better assure that noprecipitates, scale and the like will be generated from the treatedhydrocarbon based liquids or contaminated aqueous solutions for a periodof time such as hours, days, or months. Most notably, according to thefirst aspect of the present invention an appropriate amount of one ormore organic acids, such as fulvic acid and humic acid, is added to theliquid being treated together with an appropriate dosage of a treatmentsolution according to the present inventors' recent proposal. Use of theorganic acid(s) together with the recently proposed treatment solutionassures that the treatment process will not only remediate the undesiredcontaminants, including H₂S, in the liquids being treated in a safe,controlled and efficient manner down to levels deemed to be safe orbelow, but will do so substantially without formation of anyprecipitate(s), scale or the like while the liquids are being treated,transported, and stored for a period of time such as hours, days orweeks.

In the treatment process according to the first aspect of the presentinvention, the remediated sulfide compounds mostly remain in the treatedliquids, but in the form of other sulfur based compounds which are nottoxic or highly dangerous, unlike the H₂S before the remediation

In the treatment process according to the first aspect of the presentinvention, the organic acid(s) and recently proposed treatment solutionmay be separately added to the liquid being treated or, in thealternative, the organic acid(s) may be added to the recently proposedtreatment solution to form a modified treatment solution, which is thenadded in an appropriate dosage amount to the liquid being treated. Thealternative approach is more convenient as a practical matter becausethe modified treatment solution may be prepared in advance at anyconvenient location, transported in a single container to anotherlocation where it is added to the liquid being treated, and permits allcomponents to be added to the liquid being treated in a single dosage.Further, testing shows that even if the several components are mixedtogether to form a modified treatment solution and the modified solutionis stored for a month or so, there are no appreciable changes to thecomposition of the modified solution and it remains effective for use inremediated contaminated hydrocarbon based liquids and contaminatedaqueous solutions.

In such treatment process according to the first aspect of the presentinvention, the standard dosage of the inventors' recently proposedtreatment solution, i.e., within a range of 0.25-6.0 ml/liter of theliquid being treated, preferably within a range of 1.0-5.0 ml/liter ofthe liquid being treated, is effective for safely and efficientlyremediating the H₂S and other contaminants therein down to appropriatelevels within a period of time such as 15 minutes-24 hours withoutcreating any significant problems for the treated liquids, substantiallythe same as in the recently proposed treatment process. Again, the mostappropriate dosage rate base within the discussed range will be based onspecific characteristics of the treated liquid and other factors asdiscussed above. However, according to the first aspect of the presentinvention an appropriate amount of the organic acid(s) is also added tothe treated liquid at a dosage rate that will typically result in aconcentration of the organic acid(s) in the liquid being treated beingin a normal range of 0.01-10 ppm, preferably 0.1-3 ppm, whether theliquid is a hydrocarbon based liquid or contaminated aqueous solution.Within such range, the most appropriate dosage rate of the organicacid(s), like the most appropriate dosage rate of the recently proposedtreatment solution, largely depends on: 1) the amount of H₂S and othersulfur containing contaminants in the liquid being treated: 2) theviscosity of the liquid; and 3) the amount of time permitted forreacting the treatment solution with the liquid being treated, althoughheating and/or mixing of the liquid being treated will reduce theviscosity of the liquid and will also reduce the amount of time requiredfor properly remediating the H₂S and other contaminants in the liquid.The dosage amount of organic acid(s) is substantially, linearly scalablewithin the discussed range based on these factors.

In the recently proposed treatment process which adds only a standarddosing rate of the treatment solution according to the presentinventors' recent proposal to a liquid being treated, there may belittle or no precipitate(s), scaling or the like formed from the treatedliquids, but even small amounts of precipitate(s), scaling or the likemay be undesired or unacceptable in some situations. In the treatmentprocess according to the first aspect of the present invention, however,the organic acid(s) which are also added to the liquids being treatedassure that substantially no precipitate(s), scaling or the like will beformed from the treated liquids while they are are being treated,transported and/or stored for a period of time such as hours, days orweeks. Further, to any extent that there is a increased likelihood thatprecipitate(s), scaling or the like may be formed in a treated liquid.e.g., the treated liquid contains an especially high content of H₂S andother sulfides requiring a larger dosage of the treatment solutionaccording to the inventors' recent proposal and/or the liquid beingtreated contains a high content of rag components such as organicmatter, an increased amount of the organic acid(s) may be added to thetreated liquid beyond the normal range of 0.01-10 ppm, preferably 0.1-3ppm, to assure that substantially no precipitate(s), scaling or the likewill be formed.

One particular application in which it is very important to assure thatno precipitates, scale and the like will be generated from the treatedhydrocarbon based liquids is when crude oil directly from the ground isbeing transported via tanker truck or other vessel to a major pipeline,which then transports the crude oil to a refinery. The major pipelinegenerally will not accept crude oil containing more than 5 ppm H₂S. Bytreating the crude oil with a standard dosage of the treatment solutionaccording to the present inventors' recent proposal, this would beeffective to reduce the H₂S content down to 5 ppm or less, but it isquite possible that there would be some precipitates and/or scaling willbe formed or deposited on surfaces of the tanker truck or other vesseltransporting the crude oil, which would be undesirable. However, by alsoadding an appropriate amount of the organic acid(s) to the treatedliquid according to the first aspect of the present invention, thisassures that essentially no precipitates or scaling will be formed fromthe treated hydrocarbon based liquids, including crude oil.Significantly, the treatment solution and process according to thepresent invention do not have any particularly detrimental effects onthe treated liquids, but do significantly improve some characteristicsof the treated liquid beyond remediating the H₂S and other contaminantsdown to safe, acceptable levels. For example, a treated hydrocarbonbased liquid such as crude oil will not only have H₂S levels reduced tosubstantially zero, but will also have a substantially neutral pH ofabout 7, so that it will cause less problems for the transportingvessel, the major pipeline and the distillation process in comparison tothe untreated crude oil which will typically include up to 2000 ppm H₂Sand have a somewhat acidic pH of 5-5.5. Further, testing performed ontreated crude oil shows that the content of light end components of thetreated crude oil, including benzene, tends to be improved—increasedsomewhat by the treatment process. Moreover, the treated crude oilhaving improved characteristics will typically be more valuable than theuntreated crude oil and can be sold at a higher price, e.g., $5 to $10per barrel. While the treated crude oil may contain some residualamounts of hydroxide(s), organic acid(s), and/or other components addedduring the treatment process, these are not particularly harmful tocrude oil itself, the transporting vessel and the major pipeline.

According to a second aspect of the present invention, a treatmentprocess according to the present inventors' recent proposal is furthermodified by also adding a small amount of monoethanolamine or MEA(C₂H₇NO) to the treated liquid, along with appropriate amounts of therecently proposed treatment solution and of the organic acid(s) such asdiscussed in relation to the first aspect of the present invention. Anappropriate small amount of the MEA to be added in the treatment processaccording to the present invention will typically correspond to aconcentration of 0.5-15 ppm, and preferrably 1.0-10 ppm, of the MEA inthe hydrocarbon based liquid or aqueous solution being treated. Withinsuch range, again, a most appropriate dosage rate for the MEA largelydepends on a few factors, e.g., 1) the amount of H₂S and other sulfurcontaining contaminants in the liquid being treated; 2) the viscosity ofthe liquid being treated; and 3) the amount of time permitted forreacting the treatment solution with the liquid being treated, whilenoting that heating and/or mixing of the treated liquid will typicallyreduce the viscosity of the liquid and reduce reaction time required forsufficiently remediating the H₂S and other contaminants in the treatedliquids. The amount of MEA is generally, linearly scalable within thediscussed range based on these three factors.

MEA added in small amounts to the treated liquids according to theeffectively functions as an anti-scaling agent and is also moreeffective at remediating some species of sulfur compounds than are thehydroxide(s) in the recently proposed treatment solution. Hence, thetreatment process including MEA according to the present inventionachieves a more complete remediation of various species of sulfurcontaining compounds.

This is different from the conventional amine treatment process in whichrelatively large amounts of MEA are added to hydrocarbon based liquidssuch as crude oil as the primary component to remediate the H₂S in thehydrocarbon based liquids. MEA exothermically reacts with hydroxide(s)such as NaOH and KOH. Correspondingly, the higher the dosage of MEAadded for treating a liquid in the treatment process of the presentinvention the greater the amount of the hydroxide(s) in the recentlyproposed treatment solution, which is also added to the treated liquidas part of the treatment process, will react with the MEA rather thanwith H₂S and other sulfur containing contaminants in the treated liquid.This would be counterproductive and undesirable. Hence, only a smallamount of MEA within the discussed range will typically be added in thetreatment solutions according to the second aspect of the presentinvention, i.e., an amount sufficient to function as an anti-scalingagent, but not so large as to significantly reduce the effectiveness ofthe hydroxide(s) in remediating the H₂S and other sulfur containingcontaminants. As with the organic acid(s), the MEA may be added to therecently proposed treatment solution so as to form a modified treatmentsolution which is then added to the liquid being treated, or the MEA maybe added to the liquid being treated separately from the recentlyproposed treatment solution and from the organic acid(s). Again,however, even if MEA is added to the recently proposed treatmentsolution and stored for a month or so, testing shows that this does notchange the content of the components of the modified treatment solutionto any appreciable extent.

Intent of Disclosure

Although the following disclosure offered for public dissemination isdetailed to ensure adequacy and aid in understanding of the invention,this is not intended to prejudice that purpose of a patent which is tocover each new inventive concept therein no matter how it may later bedisguised by variations in form or additions of further improvements.The claims at the end hereof are the chief aid toward this purpose, asit is these that meet the requirement of pointing out the improvements,combinations and methods in which the inventive concepts are found.

DETAILED DESCRIPTION OF PRESENT EXEMPLARY EMBODIMENTS TreatmentSolutions and Treatment Methods—Exemplary Embodiments

According to exemplary embodiments of the present invention, there isprovided treatment solutions and treatment processes which use thetreatment solutions for treating hydrocarbon or petroleum based liquidssuch as crude oil, diesel fuel, etc., as well as for treatingcontaminated aqueous solutions such as water extracted from the groundwith crude oil and natural gas, to remediate hydrogen sulfide (H₂S),other sulfur-containing compounds, and other contaminants in suchliquids down to acceptable levels, while at the same time assuring thatthat substantially no precipitates, scale or the like will be generatedfrom the treated liquids for a period of time such as hours, days, ormonths.

Remediating H₂S is a primary focus and advantage of the treatmentsolutions and processes according to the exemplary embodiments of thepresent invention because H₂S is very toxic and corrosive, is typicallypresent at elevated levels in crude oil and natural gas as extractedfrom the ground, as well as in aqueous solutions extracted from theground with crude oil or natural gas, and the acceptable content of H₂Sin hydrocarbon based liquids and aqueous solutions is highly limited andregulated. The inventors' recently proposed treatment solution andtreatment process are very effective and efficient at remediating H₂S inhydrocarbon based liquids and contaminated aqueous solutions asdisclosed in PCT/US2018/050913. In addition to remediating H₂S, however,in some situations it is also very important that substances generatedin the remediation of H₂S and other sulfur-containing compounds, as wellas other contaminants present in the treated liquids, not be releasedfrom the treated liquids as precipitate(s), scaling or the like whilethe liquids are being treated, transported or stored for periods oftime, and this is another important focus of the present invention. Oneparticular application in which it is very important to assure that noprecipitates, scale and the like will be generated from a treatedhydrocarbon based liquid is when crude oil directly from the ground isbeing transported via tanker truck or other vessel to a major pipeline,which then transports the crude oil to a refinery. In relation totreated aqueous solutions, such solutions are sometimes used inindustrial applications, including for boilers, chillers, hide tanningprocesses, processes involving wood pulp and paper, etc. wherein it isimportant that precipitates, scaling and the like not be released orgenerated from the treated aqueous solutions.

A treatment solution and treatment process according to exemplaryembodiments of the present invention are modifications of the treatmentsolutions and treatment processes recently proposed by the presentinventors as disclosed in PCT/US2018/050913, and generally involve useof the recently proposed treatment solution for efficiently remediatingH₂S and other contaminants in hydrocarbon based liquids and aqueoussolutions, together with one or more additional substances whichfunction to prevent the remediated contaminants and other contaminantsin the treated liquids from being released as precipitate(s), scaling,or the like. In the treatment processes according to the presentinvention, an appropriate amount of the recently proposed treatmentsolution is used and functions to remediate the H₂S and othercontaminants in the treated liquids down to acceptable levels inessentially the same manner as explained in PCT/US2018/050913, while theadditional substance(s) are added in appropriate amount(s) and functionto assure that substantially none of the remediated contaminants andother contaminants in the treated liquids will be released from thetreated liquids as precipitate(s), scaling or the like while the liquidsare being treated, transported or stored for periods of time. Accordingto a present exemplary embodiment of the invention, such additionalsubstances primarily include at least organic acid, such as fulvic acidand humic acid. When such organic acid(s) are also added to the treatedliquids, even at relatively low concentrations, e.g., 3 ppm or less,they are very effective at preventing formation of precipitates, scaleand the like from the treated liquids. Another substance which may alsobe used in an embodiment of a treatment process according to the presentinvention is monoethanolamine (MEA). When also added to the treatedliquids at relatively low concentrations, e.g., 15 ppm or less. MEAfunctions effectively as an anti-scaling agent, and also provides otherbeneficial functions, including remediation of some other contaminants,as discussed herein.

For a clear understanding of the present invention, below there is firstpresented (I) a discussion of the inventors' recently proposed treatmentsolution and treatment process such as disclosed in PCT/US2018/050913for remediating H₂S and other contaminants, followed by (II) adiscussion of embodiments of a treatment solution and treatment processaccording to the present invention, in which the additional substance(s)are used together with the inventors' recently proposed treatmentsolution and treatment process for treating various contaminated liquidsto remediate H₂S and other contaminants in the liquids, while preventingformation of precipitate(s), scaling and the like.

(I) The Treatment Solution and Treatment Process

According to the Inventors' Recent Proposal

According to the inventors' recent proposal as disclosed inPCT/US2018/050913, a treatment solution appropriate for remediating H₂S,other sulfur-containing compounds, and other contaminants incontaminated hydrocarbon based liquids and aqueous solutions is aqueousbased and may primarily include one or more hydroxides, such as sodiumhydroxide (NaOH) and potassium hydroxide (KOH), at a collective, highconcentration of 35-55 weight percent, and preferably at least 45 weightpercent, of the aqueous treatment solution, and a treatment process forremediating H₂S and other contaminants in the liquids being treatedincludes steps of adding a standard dosage of such treatment solutionwithin a range of 0.25-6.0 ml/liter of the liquid being treated,preferably within a range of 1.0-5.0 ml/liter of the liquid beingtreated, which corresponds to approximately 125-3000 ppm of hydroxide(s)in the liquid being treated, and permitting the treatment solution toreact with the liquid being treated for a time period of 15 minutes-24hours. The discussed standard dosage amount in the treatment processaccording to the inventors' recent proposal is generally effective forH₂S concentrations up to 40,000 ppm. If the concentration of H₂S ishigher than 40,000 ppm it may be necessary to increase standard dosageamount of the recently proposed treatment solution appropriately, whichmay generally involve linear scalability. The recently proposedtreatment process may cause precipitate(s), scale and the like, as wellas gas(ses), to be generated and/or released from the treated liquids,and to any extent this occurs the treatment process according to therecent proposal may include additional steps of collecting, dischargingand treating any precipitates and/or gases generated by the reactionsbetween the treatment solution and the liquids being treated. Accordingto the present invention, however, there should be very little or noprecipitates, scaling and/or gases generated by the treatment process.

The most appropriate or optimum dosage amount of the recently proposedtreatment solution within the discussed range will vary, with generallylinear scalability, based on a few factors. These factors include:specific content of the liquid being treated including the amount of H₂Sand other contaminants contained therein, the viscosity of the liquidbeing treated, whether the treated liquid is being agitated and/orheated, and the amount of time permitted for reacting the treatmentsolution and the petroleum based liquid. Such treatment solutionaccording to the recent proposal may further include one or more othercomponents depending on the specific characteristics of the liquidsbeing treated, and other factors relating to the remediation treatmentprocess. Characteristics of the liquids include the viscosity thereof,the particular contaminants therein along with H₂S, and the amounts ofeach of H₂S and the other contaminants contained in the liquids. WhileH₂S is the main contaminant which must typically be remediated in theliquids being treated, such as crude oil, it may be necessary ordesirable to also remediate the other contaminants besides H₂S in theliquids, and the other contaminants may also create complications forremediating the H₂S. For example, if crude oil is the liquid beingtreated and contains an appreciable amount of carbon dioxide (CO₂), thismay affect the treatment process because hydroxide(s) contained in therecently proposed treatment solution may react with carbon dioxide inthe presence of trace amounts of water according to the followingequation (3), whereby it may be necessary to use an additional amount ofhydroxide(s) for treating the crude oil, e.g., by increasing the dosageamount of the recently proposed treatment solution added to the crudeoil.CO₂+NaOH(aqueous)→NaHCO₃  (3)

Other important factors pertaining to the treatment process forremediating contaminants in the liquids include permitted reaction time,whether the treated liquid is being agitated and/or heated, and the typeof remediation desired. If liquids that are being treated are highlyviscous, heating and/or mixing may be desirable or necessary to dispersethe recently proposed treatment solution throughout the treated liquidwithin a reasonably short time such as 1-3 hours. Mixing at moderate tohigh speeds may reduce required reaction time by 50% or more. In termsof the type of remediation desired, it is important to know whetherthere are any restrictions on the amounts of precipitate(s) and/or gasesthat may be released from the treated liquids, whether it is desired togenerate a certain precipitate or gas via the treatment, etc., asdifferent amounts of the recently proposed treatment solution that areused per given unit of the liquid being treated will achieve differentresults, as discussed herein.

Generally, if the liquid being treated is a medium to light crude oiland the amount of H₂S is relatively low, e.g. 20 ppm-100 ppm the mostappropriate dosage rate may be toward the lower end of the standardrange, whereas if the amount of H₂S is relatively high, e.g. 20,000ppm-40,000 ppm the most appropriate dosage rate may be toward the higherend of the standard range, and most appropriate dosage rates forintermediate amounts of H₂S would be at correspondingly intermediatevalues of the standard range. The recently proposed treatment processmay be conveniently carried out essentially wherever the contaminatedliquids may be present, e.g., in open bodies of the liquids, inconjunction with a transport tanker or other vessel in which the liquidsare being transported, at a wellhead where the liquids are beingextracted from the ground, in open or closed tanks, in an enclosedpipeline through which the contaminated water or other liquid is beingtransported, etc.

Similarly, as the viscosity of a hydrocarbon based liquid being treatedincreases, or the API gravity of the liquid decreases, the mostappropriate amount of the treatment solution to be used in a treatmentprocess according to the inventors' recent proposal will generallyincrease. The treatment solution, including hydroxide(s), has goodmigration characteristics when added to thin, low viscosity hydrocarbonbased liquids with an API gravity of 33° or more and can readilydisperse throughout the liquids, although the liquids could be heatedand/or mixed to increase the rate and/or uniformity of dispersion, whichwill reduce required reaction time for remediating H₂S. For mediumviscosity hydrocarbon based liquids with an API gravity of about23°-33°, mixing by stirring at low-moderate speeds, e.g., 100-500 rpm orother appropriate manner, and/or heating to temperatures below the flashpoint of the liquids is helpful to disperse the treatment solution inthe liquids. For highly viscous hydrocarbon based liquids with an APIviscosity of 15° or less, heating to temperatures below the flash pointof the liquids together with mixing is generally required to properlydisperse the treatment solution in the liquids. Different types ofhydrocarbon liquids include light crude oil (API gravity ≥31.1), mediumcrude oil (API gravity between 23.3° and 31.10), heavy crude oil (APIgravity <23.3°), bunker fuel (API gravity approximately 60), diesel fuel(API gravity approximately 340), etc. Hydrocarbon based liquids with anAPI gravity of less than 10° are heavier than water, are extremelyviscous and will sink in water. In terms of the dosage rates for thetreatment solution, if the hydrocarbon based liquid contains 2,000 ppmor less of H₂S, for low viscosity (API gravity of 33° or more)hydrocarbon based liquids such as diesel fuel, a most appropriate dosageamount may be 1-2 ml/liter of based liquid, while for medium viscousliquids (API gravity of 20°-30°) such as light, medium or heavy crudeoil, a most appropriate dosage amount may be 2-3.5 ml/liter of thehydrocarbon based liquid, and for highly viscous petroleum based liquids(API gravity of 15° or less), such as bunker fuel, a most appropriatedosage amount may be 5-6 ml/liter of the hydrocarbon based liquid. Forcontaminated aqueous solutions, viscosity is typically not a significantfactor for determining the most appropriate treatment dosage of therecently proposed treatment solution because the viscosity ofcontaminated aqueous solutions is typically low and the treatmentsolution readily disperses—migrates throughout the liquid, even withoutmixing or heating.

As far as reaction time permitted, there may no restriction thereon andthe treatment solution may be permitted to react for any suitable timesuch as 15 minutes-24 hours at a most appropriate dosage rate based onthe concentration—amount of H₂S contained in the particular liquid andthe viscosity (API gravity) of the liquid in a treatment processaccording to the inventors' recent proposal. However, there may besituations where reaction time is limited, e.g., limited to an amount oftime required to transport the hydrocarbon based liquid to a desireddestination for unloading after the treatment solution has been added tothe liquid, limited to less than 30 minutes based on desiredproductivity, etc. In such situations with limited reaction times, amost appropriate dosage amount of the treatment solution to be added tothe liquid according to the inventors' recently proposed treatmentprocess may be increased above the standard dosage amount as determinedbased on based on the concentration—amount of H₂S contained in theparticular liquid and the viscosity (API gravity) of the liquid. e.g.,increased to an amount that will assure essentially complete remediationof the H₂S contained in the particular liquid within the time permitted.For example, if a normal reaction time required to fully remediate H₂Scontained in the particular liquid is 2 hours, but the permittedreaction time is only 1 hour, a most appropriate dosage amount may betwice that of a standard dosage amount determined based on theconcentration—amount of H₂S contained in the particular liquid and theviscosity of the liquid.

According to one study performed by the present inventors, when a crudeoil containing about 1000 ppm H₂S was treated with a treatment solutionaccording to the inventors' recent proposal which contained NaOH asapproximately 99% of the total hydroxides therein. KOH as the other 1%of hydroxides therein and total hydroxide concentration of approximately50 wt % in the solution, when 0.25 ml of the treatment solution wasadded/liter of the crude oil it took approximately 12 hours to remediateor abate the H₂S down to approximately 0 ppm, whereas when 5 ml of thetreatment solution was added/liter of the crude oil it tookapproximately 30 minutes to abate the H₂S down to approximately 0 ppm.In a similar study performed by the inventors, essentially the sameresults were obtained with a treatment solution according to theinventors' recent proposal containing KOH as approximately 99% of thetotal hydroxides therein, NaOH as the other 1% of hydroxides therein andtotal hydroxide concentration of approximately 50 wt % in the solutionwas used in the same quantities to treat the same crude oil.

A complicating factor in treating hydrocarbon based liquids such ascrude oil to remediate the H₂S and other contaminants therein is thefact that the naturally occurring crude oil and natural gas, as well asaqueous solutions extracted from the earth along with crude oil andnatural gas, extracted at any given place and time always have uniquecharacteristics that must be considered. For example, even in relationto one given oil well or natural gas well, the crude oil, natural gasand aqueous solutions extracted therefrom have characteristics which canvary greatly, e.g., crude oil extracted from a given well at a giventime on a given day, can contain amounts of H₂S, as well as varioustypes and amounts of other contaminants, which are significantlydifferent from those contained in crude oil extracted from the same wellon the same day, but at a different time. The treatment solutions andtreatment processes according to the inventors' recent proposal aresuitable for remediating the H₂S, as well as various other types andamounts of other contaminants, in any of such liquids.

According to an advantageous aspect of the recently proposed treatmentsolution and treatment process, a given or standard blend of thetreatment solution may be used for treating a wide variety of differentliquids, whether hydrocarbon or water based, and for treating suchliquids which contain different amounts of H₂S and other contaminants.For example, addition of a moderately excessive amount of the treatmentsolution above the standard dosage range will generally assure that theH₂S and other contaminants will be remediated down to acceptable levels,but will not detrimentally affect the treated liquid to any significantextent. Thus, for example, it may be advantageous and/or convenient toadd 1.5 times a standard dosage amount of a standard blend the treatmentsolution to a given liquid to ensure that the H₂S and other contaminantsin the liquid will be sufficiently remediated down to acceptable levels,rather than carefully analyzing the given liquid and determining a mostappropriate dosage of the treatment solution based on the analysis.While the cost of the treatment may be increased because additionaltreatment solution is being used, the additional cost may be acceptablein some situations. On the other hand, if the dosage amount of thetreatment solution is 2-5 times the standard dosage amount, this maycause additional results such as formation and release of variousprecipitates and other contaminants, and if the dosage amount of thetreatment solution is 10 times the standard dosage amount this may causethe treated liquid to become caustic as discussed herein.

It is conventionally understood that an aqueous solution of hydroxidesuch as NaOH will react with H₂S in petroleum based liquids such ascrude oil. Generally, H₂S is an acidic compound, crude oil as extractedfrom the ground and containing a typical amount of H₂S. e.g. ≤2000 ppm,which is mostly in the form gas dissolved in the crude oil, has amoderately acidic pH of about 5-5.5. Gaseous H₂S does not exist insolution above a pH of about 7. A treatment solution according to thepresent inventors' recent proposal contains a large percentage ofhydroxide(s), is basic with a pH of about 13-14, and when added to thepetroleum liquid increases the pH thereof. The water and hydroxide(s) inthe treatment solution are used to extract H₂S from the crude oil intothe water, thereby dissociating H₂S to HS— ion at higher pH, whichshifts the equilibrium of H₂S gas from oil to water. Then, the HS— canreact with sodium to form NaHS (sodium bisulfide), or with S₂— to formNa₂S (sodium sulfide), for example, plus water as a byproduct accordingto the equations (1), (2) discussed herein.

The present inventors recent proposal is based on their discovery thatthe conventional treatment methods, using a caustic aqueous solutionconsisting of up to 20 weight percent sodium hydroxide (NaOH) in waterare not efficient, and that the H₂S can be much more efficientlyremediated using a more highly concentrated, aqueous hydroxide solution;e.g., including as a primary component 35-55 weight percent, andpreferably at least 45 weight percent, of one or more hydroxides, suchas sodium hydroxide (NaOH) and potassium hydroxide (KOH). Based on theinventors' investigations they determined that:

1) the liquid-liquid extraction aspect of the conventional methods isactually not that important in comparison to the chemical reactionaspect. e.g., because the initial solubility of H₂S into water, as givenby Henry's Law, is low;

2) the larger amounts of water used in aqueous treatment solutionsaccording to the conventional methods also function to dilute the NaOH,which is undesirable because this significantly slows the process neededto produce ionized HS— and S₂— ions that allow more of the H₂S containedin the petroleum liquids to go into the water, and

3) it is much more efficient and effective to remove thesulfur-containing compounds primarily though a chemical reaction processand to a much lesser degree a liquid-liquid extraction though use of athe aqueous treatment solution containing a very high concentration ofhydroxide(s), provided that the amount of caustic (hydroxide) used iscarefully limited within a controlled range, which accounts for factorsincluding stoichiometry of intended reactions and desired rate ofreaction.

Although there are many different common compounds of hydroxide (OH⁻)that may be used in the treatment solution according to the recentproposal, many of these have undesirable characteristics associatedtherewith, including that they would introduce other contaminants intothe treated liquids which may require further remediation step(s), highcost, etc. For example, iron, other metals, calcium, barium, andchlorides interfere with heat and cracking in refining processes andwould have to be removed from treated crude oil before it is refined. Onthe other hand sodium, potassium, magnesium, and manganese, arepermitted in refining processes as long as the content is not too high,e.g., <250 ppm, so that hydroxides of these elements would beappropriate if the treatment solution is being used for treating crudeoil.

Sodium hydroxide is very effective for use in the recently proposedtreatment solution because it does not harm the hydrocarbon basedliquids when used in appropriate amounts. For example, if NaOH is usedexclusively or primarily as the hydroxide in the treatment solution at aconcentration of about 50 weight percent, and the solution is used at astandard dosing rate to treat crude oil in a treatment process accordingto the inventors' recent proposal, this may increase sodium content inthe treated crude oil from about 10 ppm to about 50 ppm. At such contentlevel the sodium does not detrimentally affect the crude oil to anyappreciable extent. Further, the recently proposed treatment solutiondoes not introduce any other contaminants into the crude oil that wouldrequire further remediation step(s), and the treatment solution isrelatively inexpensive. Potassium hydroxide (KOH), magnesium hydroxide(Mg(OH)₂), and manganese hydroxide (Mn(OH)₂, Mn(OH)₄) are some othersuitable hydroxides for use in the recently proposed treatment solution.

Use of a combination of hydroxides is advantageous for more completelyreacting with and remediating most or all of the sulfides in thehydrocarbon based liquids and contaminated aqueous solutions, notingthat there are more than 300 types of sulfides and NaOH is not the mostsuitable hydroxide for treating each of the different sulfides. Ofcourse, hydrogen sulfide H₂S is by far the main contaminant that must beremediated. Potassium hydroxide (KOH), for example, is more effectivethan sodium hydroxide for reacting with some species of sulfides. Hence,if the treatment solution according to the inventors' recent proposalcontains some amount of potassium hydroxide (KOH) together with thesodium hydroxide, the treatment solution achieves a more completereaction with all of the sulfur contained in the petroleum based liquidsin comparison to just using a treatment solution of sodium hydroxide.For example, the treatment solution according to the recent proposal maycontain a blend of 50-99.9 parts NaOH: 0.1-50 parts KOH, at a totalhydroxide concentration of 35-55 weight percent in the treatmentsolution, and preferably at least 45 weight percent in the treatmentsolution. Again, such treatment solution according to the recentproposal is highly alkaline with a pH of 13-14.

Also, aqueous solutions of different hydroxides will freeze at differenttemperatures, even if the solutions have the same collectiveconcentrations of the different hydroxides, and this may be an importantconsideration. For example, if the treatment process is to be conductedat an ambient temperatures near, at or below 0° C., it may be desirableto use a treatment solution containing a collective high concentrationof 35-55 weight percent, and preferably at least 45 weight percent, ofone or more hydroxide(s) wherein the treatment solution has a freezingtemperature below the ambient temperature so as to avoid anytemperature-related complications such as freezing or gelling of thetreatment solution and/or the treated liquid, e.g., a treatment solutioncontaining KOH as the primary hydroxide has a freezing temperature lowerthan that of a treatment solution containing NaOH as the primaryhydroxide by at least 10° C.

The recently proposed treatment process provides unexpectedly goodresults for efficiently remediating the H₂S, other sulfur basedcontaminants and other contaminants in both hydrocarbon based liquidsand aqueous solutions. For example, according to conventionalunderstanding at the time of the inventors' recent proposal it wascounterintuitive to limit the amount of water in the remediation processwhen applied to hydrocarbon based liquids such as crude oil because thislimits chemical contact with the contaminants in the hydrocarbon basedliquids, e.g., the chemical reactants are mostly ionic and readilydissolve in water, but not in the petroleum based liquids such as crudeoil. However, the present inventors have discovered that since thechemical reactions involved between hydroxides and sulfur basedcontaminants including H₂S, e.g., equations (1), (2) above, producewater, the produced water can readily diffuse through the hydrocarbonbased liquid being treated as it is produced because the causticsolution has good migration tendencies in many hydrocarbon based liquidsand the diffusion may also be enhanced by agitation and/or heating ofthe treated liquids. Correspondingly, the inventors also found that itis unnecessary to add any significant amount of water in the treatmentprocess apart from the water in the treatment solution in order for thehydrocarbon based liquid to be effectively treated for remediation ofsulfur-containing contaminants, including H₂S, and other contaminantstherein. An exemplary treatment process according to the inventors'recent proposal as discussed herein is not a wash type process, butrapid chemical reactions that greatly reduce the mass transfer of thegas to aqueous phase.

What the treatment process according to the recent proposal doesdifferently, in comparison to the conventional treatment processes forremediating hydrocarbon based liquids, is to essentially reduce theinitial amount of water to the minimum effective amount, while carefullylimiting the amount of hydroxides and possibly other reactants in thetreatment solution to appropriate amounts, for reacting with thecontaminants in the hydrocarbon based liquid being treated based onconsiderations of stoichiometry, desired reaction rate and specificresult desired, and by this the efficiency of the process is increasedin multiple aspects in comparison to conventional treatment processesknown at the time of the inventors' recent proposal. One aspect is thatexcessive amounts of the treatment solution are not used and wasted.Another aspect of increased efficiency is that more of the hydrocarbonbased liquid may be treated for any given size treatment batch/tankbecause there is less amount of water in the batch/tank. As anotherexample, the volume of resulting waste that must be removed and possiblytreated is reduced as well. Further, as a main component of thetreatment solution, highly concentrated aqueous solutions of hydroxidesare commercially available in appropriately high concentrations fordirect use in the treatment solution, e.g., concentrated aqueoussolutions of NaOH are available in concentrations of 47 weight percentNaOH (17.6 M) and 50.5 weight percent NaOH (19.4 M), which may bedirectly used in the exemplary embodiment of the present inventionbecause no efforts need be made to dilute the commercially availableNaOH solutions to a lesser concentration with water.

The present inventors have found that if the reactions involved in thetreatment process according to their recent proposal are properlycontrolled by dosing the treatment solution within the standard range of0.25-6 ml/liter of hydrocarbon based liquid, preferably within a rangeof 1.0-5.0 ml/liter of the petroleum based liquid, and a reaction timesuch as 15 minutes to 24 hours according to the recent proposal, thenthe hydroxides in the treatment solution will react with the sulfurpreferentially over other species in the hydrocarbon based liquids suchas crude oil and will not harm the hydrocarbon based liquids. Forexample, the present inventors have found that a dose of the treatmentsolution according to the recent proposal within the standard range doesnot harm the hydrocarbon based liquids and completely remediates the H₂Scontained therein down to 5 ppm or less, and typically down tosubstantially 0 ppm. Any residual caustic substances, includinghydroxide(s), resulting from the treatment process according to therecent proposal will typically not harm the hydrocarbon based liquidsbecause it will be a relatively small residual amount. Also, residualhydroxides tend to be contained in an aqueous portion of the hydrocarbonbased liquids, i.e., a portion containing the water from the treatmentsolution and water produced in reactions between the hydroxides in thetreatment solution and the sulfur containing compounds in thehydrocarbon based liquids and may be readily separated from thehydrocarbon based liquids.

When the treatment solution according to the inventors' recent proposalcontains sodium hydroxide (NaOH) as the primary hydroxide containedtherein. e.g., at least 90% of the hydroxides, much of the H₂S. e.g., atleast 60% is converted into sodium bisulfide (NaHS) according to thereaction (1) above, which remains dissolved in the treated petroleumliquid, and does not create any significant problems that would need tobe addressed, e.g., this would not prevent the crude oil from beingaccepted as sweet, high grade crude oil. Additionally, some of the H₂Smay be converted into sulfur dioxide (SO₂) gas, e.g., upon stirringwhich allows air containing oxygen to get into the oil, which may bereleased from the treated petroleum based liquid, depending on thepressure under which the treated liquid is kept. Generally, hydroxidesincluding NaOH are reducing agents and would not produce sulfur dioxideor elemental sulfur if the treated hydrocarbon based liquid is notexposed to air. However, if the oil is exposed to air, thesulfide/bisulfide can be oxidized to SO₂ or to elemental sulfur. Allsulfide species are the same oxidation state (−2) and NaOH is notchanging the oxidation state. Similar reactions would occur for otherhydroxides included in the treatment solution. Relative to any suchsulfur dioxide (SO₂) gas, as well as any other gases that may bereleased from the treated crude oil, it would be necessary as a safetymeasure to provide some head space in a closed tank or other closedvessel transporting the treated liquid to assure that the pressure doesnot get excessively high.

Although the treatment process according to the inventors' recentproposal will increase the content of sodium (Na) in the treated liquidwhen the treatment solution contains sodium hydroxide as the primaryhydroxide contained therein, this does not cause any problems ordetrimental effects when the crude oil is refined and subsequentlycombusted. For example, a study performed showed that for crude oil witha starting concentration of about 8 ppm Na and about 1000 ppm H₂S, aftertreatment using 3 ml of the treatment solution according to theinventors' recent proposal/liter of the crude oil, the finalconcentrations were about 40 ppm Na and 0 ppm H₂S. Sodium has no adverseeffects in the crude oil refining process as long as the concentrationof sodium is generally ≤250 ppm.

Moreover, the abatement of the H₂S by the treatment process according tothe inventors' recent proposal is desirably non-reversible, unlike H₂Sabatement achieved by a conventional amine treatment process which usesan amine such as MEA or triazine for treating H₂S in crude oil. Forexample, with the conventional amine treatment process, while the H₂Smay be initially remediated or abated down to acceptable levels, thesulfur contained in the treated oil may undesirably revert back to H₂Sover time, especially if the treated oil is heated. Conversely, whencrude oil which initially contained about 1000 ppm H₂S was treatedaccording to a treatment process using the treatment solution accordingto the inventors' recent proposal at a dosing rate of 3 ml/liter of oiland the H₂S was abated down to about 0 ppm and essentially none of thesulfur precipitated out of the oil, the treated crude oil was heated upto 180-300° F. or 82.2-148.9° C. for periods of hours, days and weeks,the resulting oil still contained about 0 ppm H₂S. Essentially none ofthe sulfur compounds(s) in the treated liquid reverted back to H₂S.

The recently proposed treatment process involving addition of thetreatment solution at the appropriate dosage rate within the standarddosage range discussed above will raise the pH of the treated liquid,e.g., crude oil pumped directly from the ground having a pH of about5.0-5.5 will increase to a pH of about 5.8-6.2, which changes thevalence of the dissolved H₂S gas in the liquid and permits substantiallyall of the H₂S to be abated and remediated into other compounds whichare not toxic.

At a dosage rate of less than 0.25 ml of the treatment solutionaccording to the inventors' recent proposal/liter of the contaminatedliquid being treated, the hydroxide(s) in the treatment solution may notefficiently react with H₂S and other sulfur containing compounds in thehydrocarbon based liquids, the contaminants may not be completelyabated, and the treated liquids may not meet government-establishedlimits for H₂S and other contaminants, even if there is no time limitfor the treatment solution to react with the liquid being treated. Onthe other hand, if the added amount of the treatment solution accordingto the inventors' recent proposal/liter of treated liquid is more than6.0 ml, the additional amount of the treatment solution may not improvethe efficiency of remediating the H₂S and other sulfur containingcompounds in the treated liquids per se, and may simply increase thecost of the treatment process. However, addition of an excessive amountof the treatment solution according to the inventors' recent proposalabove the standard dosage rate may be desirable for various reasons,such as those discussed in PCT/US2018/050913.

Especially in terms of amounts of contaminants remediated, and perhapsin terms of the time required for the treatment, there is generally nosignificant improvement in the remediation of H₂S in the treated liquidusing more than 6.0 ml of the treatment solution according to theinventors' recent proposal/liter of the treated liquid in comparison totreatment involving more than 6.0 ml of the treatment solution/liter ofthe same liquid. For hydrocarbon based liquids, however, unless thedosage rate is greatly exceeded, e.g., by more than 5 times the standarddosage rate for a particular hydrocarbon based liquid being treated, itis unlikely that the excess/residual amount of the caustic treatmentsolution will harm the hydrocarbon based liquid or any metalliccontainer in which the hydrocarbon based liquid is contained to anyappreciable extent. At more than 10 times the standard dosage rate forthe particular hydrocarbon based liquid, the treated liquid is likely tobe caustic and have a relatively high pH, which can be undesirablebecause it may corrode metals including steel and aluminum. Thus, it maybe important to properly dose the amount of treatment solution used inthe treatment processes according to the inventors' recent proposal inorder to be most efficient and cost effective, and in order to achievespecifically desired results. Desirably, however, even if the dosageamount used in a treatment process according to the recent proposal ismoderately or significantly excessive in comparison the optimum dosageamount within the standard dosage range based on stoichiometry and otherconsiderations, this should not create any significant problems for thetreated liquids.

The recently proposed treatment solution may include other components,again, depending on the presence of other contaminants in thehydrocarbon based liquids and contaminated aqueous solutions which areto be remediated, as well as on the desired results of the treatmentprocess. These other components may also be included in the treatmentsolution and treatment process according to the present invention. Forexample, a small amount of a silicate such as potassium silicate may beadded to such treatment solution to provide an anti bacterial function,which may be desirable for killing microbes, including sulfur eatingmicrobes. For example, 2-10 ml of a potassium silicate aqueous solutioncontaining 29-45 weight percent potassium silicate in water may be addedper liter of the recently proposed aqueous treatment solution containinga total hydroxide concentration of 35-55 weight percent therein, andthen the treatment solution containing hydroxide(s) and potassiumsilicate may be added to the liquid being treated at appropriate dosagerates within the discussed standard dosage range. Potassium silicatecomes in various ratios of SiO₂: K₂O, but is often represented asK₂SiO₃.

Other appropriate anti-bacterial agent or agents could be used inaddition to or as an alternative to silicates, depending on theparticular liquid being treated. For example, barium (Ba) may be addedin an amount of ≤100 ppm of the liquid being treated, whether ahydrocarbon based liquid or aqueous solution, and will provide anantibacterial function. Barium tends to be more appropriate for use withlighter hydrocarbon based liquids including diesel fuel and for treatingcontaminated aqueous solutions, while potassium silicate tends to bemore appropriate for use with heavier hydrocarbon based liquidsincluding crude oil. Also, barium is prohibited in hydrocarbon basedliquids which are to be refined because barium has an adverse effect onthe refining process. Therefore, barium is not preferred in the practiceof the present invention when hydrocarbon based liquids such as crudeoil are being treated.

Another component which may be included in the inventors' recentlyproposed treatment solution, which is then added to a contaminatedaqueous solution in a treatment process according to the recentproposal, is sodium bisulfite (NaHSO₃). When added at a relatively lowconcentration, e.g., 0.001-0.05 ppm/liter of liquid being treated,sodium bisulfite is very effective for displacing dissolved gases suchas methane (CH₄) contained in contaminated aqueous solutions as theseliquids are treated and transported via a tanker truck, pipeline orother manner, so that the displaced gas may be captured, collected andsold. This is, of course, very desirable and advantageous. Thus, forexample, if contaminated wastewater produced or obtained when extractingmethane-natural gas from a well contains 5% volume of methane-naturalgas dissolved therein, this can represent a significant amount ofmethane-natural gas that may be recovered, and favorably increases thetotal production of the well. An aqueous solution of sodium bisulfitemay be highly concentrated, e.g., 70-90% wt/wt, may be added to therecently proposed treatment solution at an appropriate rate to achieve aconcentration of 0.001-0.05 ppm/liter of liquid being treated. Whileaddition of sodium bisulfite may be particularly suitable for treatingaqueous solutions, it may also be added to a treatment solution used fortreating hydrocarbon based liquids. Significantly, however, if sodiumbisulfite is to be used in treating crude oil or other hydrocarbon basedliquids it should be added in hydrated form, whether in power or liquid,to function efficiently.

Additionally, hydrocarbon based liquids such as crude oil andcontaminated aqueous solutions tend to have various impurities andvarious amounts of impurities, many of which must or should beremediated along with the H₂S and other sulfur containing contaminants.These impurities include ammonia (NH₃), which tends to accumulate in thewater produced via the reactions (1), (2), carbon dioxide gas (CO₂), aswell as various solid impurities including dead—decomposing organicmatter, total suspended solids (TSS) or “rag” which typically includevarious minerals and other inorganic matters which bond to thehydrocarbons, bottom sediment and water (BSW), heavy metals, etc. Theaccumulated ammonia may be discharged as a gas from the liquid beingtreated, which is toxic and undesirable. Carbon dioxide reacts withhydroxide(s) such as NaOH in the treatment solution as discussed abovein relation to equation (3).

For remediating ammonia the pH of the aqueous portion of the liquids inthe treatment cell may be adjusted to a level such as 8.5-7.0, at whichthe ammonia is converted to ammonium ion (NH₄+) and thereby prevents theammonia from being released in gas form. However, reducing the pH of thetreatment solution may also affect the reactions between hydroxide andH₂S. At lower pH, such as 7.0-8.5. S²⁻ ions in the liquid are convertedto HS' ions, which is one step closer to H₂S, so that there will be moreresidual H₂S in the liquid when the pH is adjusted lower and lessresidual H₂S in the liquid when the pH is adjusted higher. Hence, theremay be some consideration of optimization of pH so as to achieve adesired balance between mitigation of H₂S on the one hand versusmitigation of NH₃ on the other hand. Appropriate dosing of the recentlytreatment solution in the recently proposed treatment process shouldproduce a pH of around 7-10 in a hydrocarbon based liquid being treated,whereas if ammonia is a concern, the pH should not be raised above 8.5.Thus, there is some overlap in the appropriate pH ranges for remediatingboth H₂S and NH₃, and depending on which of these contaminants ispresent and at what levels the pH can be suitably adjusted to achieve anoptimum result. Of course, remediation of H₂S is a primary focus of theinvention, and would normally be a primary factor in determining theappropriate pH for the treated liquid. It should also be noted thatoverdosing with the recently proposed treatment solution may increasethe pH above 9, and thus increases the risk of producing more ammoniagas. Hence, this is another reason why the dosage rate for the recentlyproposed treatment solution should be maintained within a standard rangeas discussed herein. An alternative approach for remediating ammonia inthe liquids being treated is to remove the ammonia from the aqueousportion of the liquid via an ion exchange process.

In regards to the rag impurities in the liquids being treated, these maybe conveniently and efficiently removed from the liquids using the sametreatment solution and treatment processes according to the inventors'recent proposal as used for reacting with the H₂S and othersulfur-containing compounds in the liquids. As discussed inPCT/US2018/050913, however, this may involve a higher dosage rate of therecently proposed treatment solution as compared to the standard dosagerate for remediating H₂S and other sulfide compounds and/or adding othersubstances which will cause formation of precipitates or the like, e.g.,components such as ferric chloride (FeCl₃) and/or ionic polymers. Forexample, adding 2-5 times the standard dosing rate of the recentlyproposed treatment solution to the hydrocarbon based liquid willgenerally cause remediated sulfur containing compounds, rag impurities,and other remaining impurities remaining in the treated hydrocarbonbased liquid to precipitate out of the liquid if so desired, whileaddition of ferric chloride (FeCl₃) and/or ionic polymers to the treatedliquid may cause flocculation which traps—bonds the contaminants andcauses them to precipitate out of the treated liquids. Of course,formation of precipitates would be contrary to one of the objects of thepresent invention, which functions to maintain the remediated sulfurcontaining compounds and other contaminants in the treated liquid forsome period of time without formation of precipitates, scaling or thelike.

Similarly, an exemplary treatment process according to the inventors'recent proposal may include additional steps of collecting, dischargingand treating any precipitates and/or gases generated by the reactionsbetween the treatment solution and the hydrocarbon based liquids. Again,however, an important aspect of a treatment process using a modifiedtreatment solution according to the present invention is thatsubstantially no precipitates, scaling or the like will be generated bythe remediated liquids while the liquids are being treated, transportedand stored for a predetermined period of time such as 30 minutes—one ormore days. Hence, a treatment process according to the present inventionshould normally not require any steps of collecting, discharging andtreating any precipitates released from the treated liquids becausethere should be no such precipitate(s), scaling or the like generated.

(II) The Treatment Solution and Treatment Process According to thePresent Invention

Again, the treatment process according to the present invention willinclude use of a dosage of the treatment solution according to therecent proposal within the discussed standard range for efficientlyremediating H₂S and other contaminants in the liquids down to safe,acceptable levels in essentially the same manner as discussed inPCT/US2018/050913, but further involves use of additional substance(s)to assure that no precipitate(s), scaling and the like are generated andreleased from the treated liquids while the liquids are being treated,transported and stored for time periods of hours, days and weeks, andwithout causing any significant problems for the treated liquid. Thetreatment process involving addition of the recently proposed treatmentsolution within the standard dosage range to a contaminated liquid maytypically generate little or no precipitate(s), scaling and the like,but to assure such result the treatment process according to the presentinvention include use of one or more additional substances along with adose of the recently proposed treatment solution within the standarddosage range.

The additional substance(s) to be used together with the recentlyproposed treatment solution according to the exemplary embodiment of thepresent invention may primarily include one or more organic acids, suchas fulvic acid and humic acid. In the treatment process according to thepresent invention, the organic acid(s) may be added to the liquid beingtreated in an appropriate collective amount that will result in a normalconcentration of 0.01-10 ppm, and preferably 0.1-3.0 ppm, in the liquid,whether the treated liquid is a hydrocarbon based liquid or contaminatedaqueous solution. Within such range, the most appropriate dosage rate ofthe organic acid(s), like the most appropriate dosage rate of therecently proposed treatment solution, largely depends on the same threefactors discussed in relation to determination of the most appropriatedosage amount of inventors' recently proposed treatment solution,i.e., 1) the amount of H₂S and other sulfur containing contaminants inthe liquid being treated; 2) the viscosity of the liquid; and 3) theamount of time permitted for reacting the treatment solution with theliquid being treated, although heating and/or mixing of the liquid beingtreated will reduce the viscosity of the liquid and will also reduce theamount of time required for properly remediating the H₂S and othercontaminants in the liquid. The dosage amount of organic acid(s) issubstantially, linearly scalable within the discussed range based onthese factors.

The organic acid(s) used according to the present invention react and/orbond with the sulfur containing compounds, including those exposed andremediated by reacting with NaOH or other hydroxide(s) in the recentlyproposed treatment solution, and are essentially all maintained in thetreated liquid, rather than being discharged therefrom as gasses,precipitate(s), scale or the like. It is possible that a small amount ofthe remediated sulfide compounds may be released from the treatedliquids as a gas such as sulfur dioxide or as a precipitate such as asulfate when the organic acid(s) are added at the discussed normalconcentrations, but the small amount is generally not significant.Further, if it is desired that no amount of precipitate(s), gas(ses),scale and the like be generated from the treated liquid, the amount oforganic acid(s) added in the treatment process may be increased abovethe discussed concentration, e.g., increased by 10-50%. Veryimportantly, the treated liquids are not detrimentally affected by thetreatment process to any significant extent, e.g., the remediatedsulfide compounds mostly remain in the treated liquids, but in the formof other sulfur compounds which are not toxic or highly dangerous,unlike the H₂S before the remediation.

Fulvic acid is actually a family of organic acids, but may typically beidentified as 1H,3H-Pyrano[4,3-b][1]benzopyran-9-carboxylic acid,4,10-dihydro-3,7,8-trihydroxy-3-methyl-10-oxo-;3,7,8-trihydroxy-3-methyl-10-oxo-1,4-dihydropyrano[4,3-b]chromene-9-carboxylicacid, with an average chemical formula of C₁₃₅H₁₈₂O₉₅N₅S₂ and molecularweights typically in a range of 100 to 10,000 g/mol. Somewhat similarly,humic acid is a mixture of several molecules, some of which are based ona motif of aromatic nuclei with phenolic and carboxylic substituents,linked together, and the illustration below shows a typical structure.Molecular weight (size) of humic acid is typically much larger than thatof fulvic acid, and can vary from 50,000 to more than 500,000 g/mol.

The organic acid(s) can be added to the treatment solution according tothe present invention in powder form, e.g., a powder containing 70-100wt % of the organic acid(s), or in an aqueous solution, e.g., an aqueoussolution containing 1-40% volume of the organic acid(s).

Another substance which may be used in the treatment processes accordingto the present invention is monoethanolamine or MEA (C₂H₇NO). MEA is aliquid organic compound and a weak base. MEA functions as a descaler andis also more effective at remediating some species of sulfur compoundsthan are the hydroxide(s) in the recently proposed treatment solution sothat the treatment process according to an exemplary embodiment of thepresent invention achieves a more complete remediation of variousspecies of sulfur containing compounds. An appropriate amount of the MEAto be used in the treatment process will typically correspond to aconcentration of 0.5-15 ppm, and preferably 1.0-10 ppm, of the MEA inthe hydrocarbon based liquid or aqueous solution being treated. Withinsuch range, the most appropriate dosage rate of MEA, again, largelydepends on the same factors as discussed in relation to the organicacid(s) and the recently proposed treatment solution, and the dosageamount of MEA is substantially, linearly scalable within the discussedrange based on these factors. MEA may be used in the treatment processaccording to the present invention directly at 100% concentration.

In the treatment process of the present invention, there are someadditional considerations relating to MEA. For one, MEA exothermicallyreacts with hydroxides such as NaOH also used in the treatment process,so that it is desirable not to include an excessive amount of MEA in thetreatment process as doing so may become counter productive to theintended function of the hydroxides for reacting with H₂S to remediatesame. MEA also can react with carbon dioxide (CO₂) according to thefollowing reversible reactionCO₂+2HOCH₂CH₂NH₂→HOCH₂CH₂NH₃ ⁺+HOCH₂CH₂NHCO₂ ⁻  (4)To any extent that MEA reacts with carbon dioxide in a treated liquid,this may reduce the amount of undesired reactions involving thehydroxide(s) also being used in the treatment process, i.e., reactionsbetween the MEA and the hydroxide(s) and reactions between carbondioxide and the hydroxide(s) according to equation (3) above. The amountof carbon dioxide in the liquid being treated may also be an importantfactor if the amount is significant, and it may be desirable to increasethe dosage amount of MEA based on the content of carbon dioxide in thetreated liquid in for liquids containing a relatively high amount ofcarbon dioxide.

Another optional component which may be included in the treatmentsolution and treatment process of the present invention is a ananti-freezing or anti-gelling agent, which may be desirable whentreating hydrocarbon based liquids such as crude oil, particularly atcold temperatures 0° C. and below, because other component(s) used inthe treatment solution and treatment process according to embodiments ofthe present invention may cause freezing or gelling in the treatedhydrocarbon based liquids at such temperatures. For example, the waterin the treatment solution according to the inventors' recent proposal inPCT/US2018/050913, the water which is generated by the reactions betweenthe hydroxide(s) and H₂S and other contaminants in the treated liquids,and the organic acids may cause gelling in treated crude oil. Althoughthe treated crude oil could be heated to prevent such gelling, it is notalways possible or practical to heat the treated crude oil. In suchsituations addition of an anti-gelling agent may be the most appropriatemanner of preventing gelling of the crude oil. One appropriate group ofanti-gelling agents is low molecular weight hydrocarbon liquidsincluding hexane and cyclo hexane, which may be added to the hydrocarbonbased liquids being treated at a dosage rate of 10% volume-25% volume ofthe collective total volume of all other components being added to thehydrocarbon based liquids being treated according to the treatmentprocess of the present invention. Thus, for example, in a treatmentprocess according to the present invention, if a large volume of crudeoil is being treated using 85 gallons of the treatment solutionaccording to the inventors' recent proposal in PCT/US2018/050913,together with 10 gallons of organic acid(s) and 5 gallons of MEA, for atotal volume of the other components equal to 100 gallons, 10-25 gallonsof hexane or cyclo hexane may also be added to the crude oil as ananti-gelling agent as part of the treatment process.

An alternative for preventing freezing or gelling of hydrocarbon basedliquids in the treatment process of the present invention, and asdiscussed above, is to select the hydroxide(s) used in the treatmentsolution according to the inventors' recent proposal such that thattreatment solution will have a freezing temperature below the ambienttemperature at which the treatment process is being conducted. Forexample, in a treatment process treating crude oil if the recentlyproposed treatment solution contains approximately equal amounts of NaOHand KOH, at a collective concentration of approximately 50 wt % of thetreatment solution, components of such treated crude oil will begingelling at approximately 0° C.-5° C., whereas if the same crude oil istreated using a treatment solution containing NaOH and KOH in a ratio of19:1 at a collective concentration of approximately 50 wt % of thetreatment solution components of such treated crude oil will begingelling at approximately 5° C.

In the treatment process according to the exemplary embodiments of thepresent invention, appropriate amounts of the inventors' recentlyproposed treatment solution for treating contaminated liquids and theadditional component(s) that prevent formation of precipitate(s),scaling, and the like, and any anti-freezing or anti-gelling agent maybe separately added to the liquids being treated or, in the alternative,one or more of the additional components may be added to the recentlyproposed treatment solution to form a modified treatment solution, whichis then added in an appropriate dosage to the liquids being treated. Thealternative approach is more convenient as a practical matter becausethe modified treatment solution may be prepared in advance at anyconvenient location, transported in a single container to anotherlocation where it is added to the liquid being treated, and permits allcomponents to be added simultaneously to the liquid being treated.Although some of the various components may react with each other insuch a modified treatment solution prior to being added to the liquidbeing treated, the amount of such reactions is small and this does notsignificantly reduce the effectiveness of treatment process incomparison to a treatment process in which each of the severalcomponents is added separately to the liquid being treated. Thus, forexample, appropriate amounts of the organic acid(s), the MEA and/or theanti-gelling agent may be added to a given volume of the inventors'recently proposed treatment solution so as to form a modified treatmentsolution so that when a quantity of the modified treatment solution isthen added to a given volume of the liquid being treated, each of thecomponents will be at the appropriate dosage rate for the given volumeof the treated liquid.

An exemplary modified treatment solution according to the presentinvention may be formed by combining 1-15 ml of an aqueous solutioncontaining 5% volume of the organic acid(s) in water and 0.05-0.5 ml ofMEA per liter of the recently proposed treatment solution containing atotal hydroxide concentration of 35-55 weight percent, and preferably atleast 45 weight percent, in water. The modified treatment solution maythen be added to the liquids being treated at appropriate dosage rates,which may substantially correspond to the standard dosing range asdiscussed in relation to the inventors' recently proposed treatmentprocess, i.e., a range of 0.25-6.0 ml/liter of the liquid being treated,preferably within a range of 1.0-5.0 ml/liter of the liquid beingtreated, noting that the amounts of organic acid(s) and MEA beingcombined with the recently proposed treatment solution in forming amodified treatment solution amount to approximately 1% of the modifiedtreatment solution. The comparatively small amount of the organicacid(s) included in the modified treatment solution does notsubstantially change basic characteristics imparted by the much largerquantity of hydroxide(s), and the modified treatment solution will havea pH substantially corresponding to that of the treatment solution notincluding the organic acid(s), e.g., 13-14, and the modified treatmentsolution will increase the pH of the liquids being treated toessentially the same extent as the recently proposed treatment solutionnot including the organic acid(s).

Again, the main important advantages achieved with the treatment processaccording to the present invention are the efficient remediation of H₂Sand other contaminants in the liquids being treated down to safe,acceptable levels while preventing precipitate(s), scaling and the likefrom being generated and released from the treated liquids while theliquids are being treated, transported and stored for time periods ofhours, days and weeks, and without detrimentally affecting the treatedliquids. For avoiding formation of precipitate(s), scaling and the like,the amount of the inventors' recently proposed treatment solution usedin the treatment process should be kept within the standard rangediscussed herein because addition of an excessive amount of the recentlyproposed treatment solution tends to promote formation ofprecipitate(s), scaling and the like. When the treatment process of thepresent invention involves use of a modified treatment solution such asdiscussed above, even if the amount of the modified treatment solutionadded/liter of a treated liquid is increased beyond the standard dosingrange, the amounts of organic acid(s) and MEA are proportionallyincreased together with the amount of hydroxide(s) in the modifiedtreatment solution and will normally still function to assure thatsubstantially no precipitate(s), scaling or the like will be formed fromthe treated liquids while they are are being treated, transported and/orstored for a period of time, even though the increased dosage of thehydroxide(s) added in the treatment process may otherwise normally tendto generate some precipitate(s), scaling or the like in the treatedliquids if the organic acid(s) and MEA were not also present.

Of course, it is also possible to separately increase the amount oforganic acid(s) and/or MEA added in the modified treatment solutionaccording to the present invention, without increasing the amount ofhydroxide(s) and other components. For example, if a treated liquid suchas crude oil has a particularly high H₂S concentration or the treatedoil is to be transported or stored for an extended period of time, e.g.,1-3 months, additional amount(s) of the organic acid(s) and/or the MEAabove the normal dosage ranges discussed above may be added to thetreated liquid to better assure that no precipitate(s), scaling or thelike will be released from the treated liquid during the extended periodof time. This would typically not create any problems for the treatedliquid, although it would increase the cost of the treatment processsomewhat.

Examples of Treatment Processes According to the Present Invention

Following are some examples of treatment processes using a treatmentsolution according to the present invention. A first group of ten (10)examples is presented in Table 1 below, in which different amounts of amodified treatment solution according to the present invention wereadded to 100 ml of a crude oil having an API gravity of 34 andcontaining 40,000 ppm of H₂S, while the crude oil was being mixed at 300rpm at a temperature of 21° C. The modified treatment solution used inthese examples combined a primary-large amount of the inventors'recently proposed treatment solution and smaller amounts of fulvic acidand MEA, such that the modified solution contained, per liter:approximately 50 wt % collectively of NaOH and KOH, with NaOH accountingfor approximately 49.5 wt % and KOH accounting for approximately 0.5 wt%; 0.1 wt % Potassium silicate K₂SiO₃; 1.0 wt % fulvic acid having amolecular formula of C₁₄H₁₂O₈ and molecular weight of 308.2 g/mol; and0.3 wt % MEA. The mixing had negligible effect on the volume ofprecipitate(s) produced. The several components of the treatmentsolution were combined prior to being added to the crude oil in each ofthe Examples.

TABLE 1 Dosage Residual Amount of Example No. Amount Reaction TimeAmount H₂S Precipitate* 1 0.1 ml 45 minutes 0.0 ml 2 0.3 ml 45 minutes0.0 ml 3 0.5 ml 45 minutes 0.0 ml 4 0.8 ml 45 minutes 5.0 ml 5 1.0 ml 45minutes 7.5 ml 6 0.1 ml 30 minutes 30 ppm  7 0.3 ml 30 minutes 12 ppm  80.5 ml 30 minutes 5 ppm 9 0.8 ml 30 minutes 3 ppm 10 1.0 ml 30 minutes 0ppm *Precipitate is solid yellow liquid which tested positive forelemental sulfur, no solid matter.

As shown in Table 1, even though the amount of H₂S in the crude oil wasfairly high at 40,000 ppm, the effectiveness in remediating the H₂S wasgenerally effective. At a dosage of 0.1 ml of the treatment solution H₂Scontent was greatly reduced down to 30 ppm, and H₂S content wasprogressively further reduced to 5 ppm with a dosage of 0.5 ml, and to 0ppm H₂S when 1.0 ml dosage of the treatment solution was added. On theother hand, no precipitate(s) were formed until the dosage rate wasincreased to 0.8 ml, which corresponds to 8 ml/liter of the crude oil,and is above the 6 ml upper limit of the standard dosage rate for theinventors' recently proposed treatment solution. Further the reactiontimes were fairly short, even though the treated liquid was being mixedwhich would normally reduce the time required for completely reactingthe treatment solution with the H₂S in the crude oil. If there is norestriction on the amount of time permitted for reacting the treatmentsolution according to the present invention with the H₂S in the crudeoil, a lesser amount of the treatment solution will be sufficient forreducing the H₂S content down to 5 ppm or less, e.g., a 2.5 ml dosagemay have been sufficient to reduce the H₂S content down to 0 ppm hadmore time been permitted.

Example 11

In this example, the liquid being treated was a light, hydrotreated,petroleum distillate with an API gravity of 53° containing 40.000 ppmH₂S vapor (as determined by ASTM D5705), 41 ppm mercaptan sulfurs (asdetermined by UOP163) and 33 ppm of H₂S in liquid (as determined byUOP163), while the same formulation of the modified treatment solutionwas used as in Examples 1-10, and was added at a dosage rate of 10ml/liter of the liquid being treated (1% based on volume). All testingfor this Example was performed by a major, accredited testing lab. Theseveral components of the treatment solution were combined prior tobeing added to the petroleum distillate, and once added were permittedto naturally migrate through the petroleum distillate without any mixingat a temperature of approximately 21° C. The treated liquid was testedfor H₂S content thirteen (13) minutes after the treatment solution wasadded thereto, and the results showed 0 ppm H₂S vapor (as determined byASTM D5705), <0.2 ppm mercaptan sulfurs (as determined by UOP163) and<1.0 ppm of H₂S in liquid (as determined by UOP163). Moreover, the samesample was stored for one month heated to elevated temperatures as highas 148° C. and again tested for H₂S content, which showed essentiallythe same results of 0 ppm H₂S vapor and nearly 0 ppm H₂S in the liquid,confirming that the H₂S remediation by the treatment process is notreversible.

Additional testing was performed on the petroleum distillate before andafter treatment pertained to sodium content, as well as HDST—HydrocarbonDistribution, and Total Light Ends. This testing showed: an increase ofsodium content from 2 mg/kg before treatment to 40 mg/kg aftertreatment, which is well within acceptable levels; no adverse effects inthe recovery or residue of the petroleum distillate, and appropriateASTM repeatability for the methods D7169 and D2887; and a slight butdesirable increase in hexanes, pentanes and butanes of the Total LightEnds (as determined by ASTM method D7900). The major testing lab whichperformed the testing further commented that: testing was performedusing the most in-depth procedures, including full crude assays, fullfractional distillations, etc., and they noted no negative effects,differences or variations on the product or fractions, the fractionsbalanced out, the fraction boiling points were well within repeatabilityrequirements, the total light ends were slightly improved, and mostimportantly the H₂S remained mitigated after passage of time and heatingto elevated temperatures.

Example 12

In this Example, the treatment solution used in Examples 1-11 was testedfor corrosiveness of aluminum and steel specimens via testing methodUNECE Section 37.4. The treatment solution was added to a crude oil withan API gravity of 33° containing 4,000 ppm H₂S vapor at a dosage rate of10 ml/liter of the crude oil (1% based on volume) and allowed to migratethrough the crude oil for 30 minutes. Then the specimens were eitherimmersed or half immersed in the treated liquid, or exposed to a gas ofthe treated crude oil, and in each case the testing lasted for 168hours. Mass loss of the specimens was detected after 168 and for eachtested specimen 0.0% mass loss was detected. Essentially, it was foundthat the crude oil as treated with approximately 1.5 times the normaldosage of the treatment solution was not corrosive to metals. The testswere also conducted for the crude oil which was treated with higherdosages of the treatment solution, and it was not until the dosageamount was increased to ten times the normal dosage amount that thealuminum specimens began to show some mass loss after 168 hours, e.g.,they became slightly pitted.

The foregoing description is given for clearness of understanding only,and no unnecessary limitations should be understood therefrom, asmodifications within the scope of the invention may be apparent to thosehaving ordinary skill in the art and are encompassed within the scope ofthe invention.

We claim:
 1. An aqueous based treatment solution for remediatinghydrogen sulfide (H₂S) and other contaminants in liquids andsubstantially without formation of precipitate, the treatment solutioncomprising: at least one hydroxide compound; at least one organic acidcomprising a fulvic acid; and water, wherein a collective concentrationof the at least one hydroxide compound in the treatment solution is in arange of 35-55 weight %, a content of water in the treatment solution isat least 30%, and a collective concentration of the at least one organicacid in the treatment solution is at least 0.01 weight %.
 2. Thetreatment solution according to claim 1, wherein the collectiveconcentration of the at least one hydroxide in the solution is 45-55weight %.
 3. The treatment solution according to claim 1, wherein thetreatment solution contains at least two different hydroxide compounds.4. The treatment solution according to claim 1, wherein the treatmentsolution contains sodium hydroxide (NaOH) and potassium hydroxide (KOH).5. The treatment solution according to claim 1, wherein the collectiveconcentration of the at least one organic acid in the solution is0.01-10 weight percent.
 6. The treatment solution according to claim 1,further comprising monoethanolamine (MEA) and a concentration of MEA inthe treatment solution is at least 0.05% volume.
 7. The treatmentsolution according to claim 1, wherein a concentration of MEA in thetreatment solution is 0.05-2.0% volume.
 8. The treatment solutionaccording to claim 1, further comprising at least one of a silicatecompound and barium as an antibacterial agent.
 9. The treatment solutionaccording to claim 1, wherein the collective concentration of the atleast one organic acid in the treatment solution is 0.01-1.0 weight %.10. The treatment solution according to claim 1, wherein collectivelythe at least one hydroxide compound and water constitute at least 95 wt% of the aqueous based treatment solution.
 11. The treatment solutionaccording to claim 1, wherein the treatment solution is configured forremediating hydrogen sulfide (H₂S) and other contaminants in crude oiland substantially without formation of precipitate.
 12. A treatmentprocess for preparing a remediated liquid from a contaminated liquidoriginally containing more than 5 ppm hydrogen sulfide (H₂S) andsubstantially without forming a precipitate, comprising steps of:preparing an aqueous solution containing at least one hydroxidecompound, in which a collective concentration of the at least onhydroxide compound in the aqueous solution is in a range of 35-55 weight% and a content of water is at least 30 weight %; adding the aqueoussolution to the contaminated liquid at a dosage amount which provides aconcentration of the at least one hydroxide compound within a range of125-5000 ppm in the contaminated liquid; adding at least one organicacid comprising a fulvic acid to the contaminated liquid at a dosagewhich provides a concentration of the at organic acid of at least 0.01ppm in the contaminated liquid; and dispersing the aqueous solution andthe at least one organic acid in the contaminated liquid and allowingthe aqueous solution and the at least one organic acid to react with thecontaminated liquid for a period of time until a concentration ofhydrogen sulfide in the contaminated liquid is reduced to ≤5 ppm. 13.The treatment process according to claim 12, wherein the dosage amountof the aqueous solution added to the contaminated liquid provides aconcentration of the at least one hydroxide compound within a range of500-2500 ppm in the contaminated liquid.
 14. The treatment processaccording to claim 12, wherein the at least one organic acid is added atthe dosage amount which provides a concentration of the at least oneorganic acid of 0.1-10 ppm in the contaminated liquid.
 15. The treatmentprocess according to claim 12, further comprising the step of addingmonoethanolamine (MEA) to the contaminated liquid at a dosage amountwhich provides a concentration of 0.5-15 ppm MEA in the contaminatedliquid.
 16. The treatment process according to claim 12, wherein theaqueous solution contains at least two different hydroxide compounds.17. The treatment process according to claim 12, wherein thecontaminated liquid is a hydrocarbon based liquid.
 18. The treatmentprocess according to claim 12, further comprising the step of combiningthe aqueous solution and the at least one organic acid before adding theaqueous solution and the at least one organic acid to the contaminatedliquid.
 19. The treatment process according to claim 12, wherein the atleast one hydroxide compound in the aqueous solution is selected toachieve a specific freezing temperature for the aqueous solution of 0°C. or less.
 20. The treatment process according to claim 12, the dosageamounts of the aqueous solution and the at least one organic acid addedto the contaminated liquid are adjusted based on at least one of theconcentration of hydrogen sulfide in the contaminated liquid, a desiredreaction time for reducing the concentration of hydrogen sulfide in thecontaminated liquid to ≤5 ppm, and a viscosity of the contaminatedliquid.
 21. The treatment process according to claim 12, whereincollectively the at least one hydroxide compound and water constitute atleast 95 wt % of the aqueous based treatment solution.
 22. The treatmentprocess according to claim 12, wherein the remediated liquid is preparedfrom contaminated crude oil originally containing more than 5 ppmhydrogen sulfide.